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January 9, 2025

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No Grid Impact from LA Fires, CAISO Says

The rapidly spreading brush fires that have devastated multiple communities around Los Angeles are not expected to affect California’s broader transmission grid, CAISO said Jan. 8.

“There’s been no impact to the power grid from the Southern California wildfire activity,” a CAISO spokesperson told RTO Insider in an email. “The bulk electric system is stable and we’re not seeing any forecasted supply interruptions, so no particular concerns. We are monitoring the potential effects and are in close coordination with state agencies and local power providers.”

At the time of publication of this article, four significant fires were burning in the L.A. metro area, including the Palisades (nearly 12,000 acres), the Eaton (more than 10,500 acres), the Hurst (more than 500 acres) and the Woodley (50 acres).

The fires, the first three of which ignited Jan. 7, have been fanned by unusually strong Santa Ana winds that at times gusted to nearly 100 miles per hour in some areas. The extreme winds prevented local fire departments and the California Department of Forestry and Fire Protection (Cal Fire) from deploying aircraft to fight the blazes, which spread quickly from house to house in a densely populated area that has seen just a fraction of its normal rainfall since the start of the water year in October.

The Hurst Fire is burning in L.A.’s Sylmar area, location of the Sylmar Converter Station, which constitutes the southern terminus of the Pacific DC Intertie, a high-voltage transmission line capable of transmitting up to 3,100 MW of electricity between Southern California and Bonneville Power Administration’s territory in Oregon. The substation is owned jointly by the Los Angeles Department of Water and Power (LADWP) and Southern California Edison (SCE).

“There is no imminent threat to the Sylmar Converter Station or any other transmission line. The Pacific DC Intertie was impacted last night but has been up and running,” LADWP spokesperson Michelle Figueroa said in an email.

“From a grid operations standpoint, it hasn’t presented any system-wide disruptions,” CAISO’s Anne Gonzales said.

Utility Responses

Both LADWP and SCE initiated public safety power shutoffs (PSPS) before and during the fires. By the afternoon of Jan. 8, nearly 183,000 of SCE’s 5 million electricity customers were subject to shutoffs, and almost 420,000 were under PSPS alerts.

LADWP reported that, as of 1 p.m., more than 155,000 of its 1.5 million customers were without power due to storm damage, while about 105,000 had been restored since the start of the storm.

“Currently, customers experiencing a power outage should expect that it could take up to 48 hours before our crews are able to respond. High winds and fire conditions continue to present hazards for our crews and can affect response times and restoration efforts,” the utility said in a statement.

The fires so far have caused two deaths, destroyed more than 1,000 structures and forced thousands of residents to evacuate their homes, with many reports of people having to abandon cars and flee on foot after becoming stuck in gridlocked traffic. At publication time, all four blazes were still 0% contained, with the cause of each still under investigation, according to Cal Fire.

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IRS Issues Low-income Clean Electricity Rules

Rules and guidance for the federal Section 48E(h) Clean Electricity Low-Income Communities Bonus Credit have been finalized and will be published shortly. 

The Department of the Treasury and Internal Revenue Service released the details Jan. 8 and said applications will be accepted starting Jan. 16. 

The 48E(h) program will provide a 10 or 20% adder on top of the 30% investment tax credit to 1.8 GW of clean electricity generation annually from 2025 through at least 2032. 

It is an expansion of the 48(e) program created by the Inflation Reduction Act. 

During its first year, 48(e) received more than 54,000 applications from 48 states, four territories and the District of Columbia. The approved applications are expected to generate investments of $3.5 billion in low-income communities and $270 million in annual offset energy costs. 

In the second year, more than 57,000 applications were submitted. Approved applications are expected to generate investments of roughly $4 billion and offset nearly $350 million a year in energy costs. 

The final 48E(h) rules contain some changes from 48(e): 

    • The range of eligible zero-emissions technologies is expanded beyond solar and wind to include hydropower, marine, geothermal and nuclear. 
    • The list of qualified housing programs has been expanded and the financial value that projects must provide to low-income households has been clarified. 
    • To steer benefits to small businesses, there is a pathway for emerging clean-energy companies to receive priority treatment of their applications. 
    • The annual 1.8-GW maximum capacity allocation is divided among four categories — 200 MW for facilities on Indian lands, 200 MW for low-income residential building projects, 800 MW for low-income economic benefit projects and 600 MW for facilities in low-income communities. 
    • This last category is subdivided — 400 MW for behind-the-meter residential facilities and 200 MW for front-of-the-meter or nonresidential behind-the-meter facilities. 

In a news release, Deputy Secretary of the Treasury Wally Adeyamo described the revisions as a pathway to greater equity: “Expanding the Clean Electricity Low-Income Communities Bonus Credit will help lower energy costs in communities that have been overlooked and left out for too long and empower developers to work alongside communities to provide tailored solutions to meet their energy and economic needs.” 

A Department of Treasury analysis of the first year of 48(e) found its results to be in line with the supply-side economics framework on which it was designed. 

“Investment in underserved people and places can lead to disproportionately higher rates of return for the nation’s economy,” Treasury said Sept. 4, “and federal investments — like the ones provided by this program — will simultaneously promote economic growth and help address inequality.” 

Some highlights from the first-year analysis: 

    • More than 54,000 applications were submitted for more than 7.2 GW of capacity; allocations went to 49,246 proposals totaling 1.475 GW and the 325 MW of eligible capacity that was not allocated was rolled over to the second program year. 
    • All of the allocations were for solar projects — few applications were submitted for wind power generation, and none were approved. 
    • More projects were awarded to applications in areas of high energy burden as defined by the Climate and Economic Justice Screening Tool than were awarded to applications in Persistent Poverty Counties. 
    • Awards were made predominantly in states with established solar markets and supportive regulations; other awards went to states with emerging solar markets, and those states are expected to make up a growing portion of the program over time. 
    • Many of the facilities that exceed 1 MW capacity will be subject to the prevailing wage and apprenticeship requirements of the Inflation Reduction Act. 
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LS Power Completes Purchase of Algonquin Power’s Renewables

LS Power has completed its $2.5 billion acquisition of Algonquin Power & Utilities Corp.’s renewable energy business, adding to its existing fleet of over 23,000 MW. 

Algonquin’s fleet includes renewables, energy storage and natural gas, along with a deep pipeline of projects at various stages of development. Generation from the deal is spread across CAISO, MISO and PJM. 

“By substantially increasing our generation capacity and pipeline of new renewable projects, we will continue to help meet rising power demand while advancing the energy transition,” LS Power CEO Paul Segal said in a statement. “We see great opportunity to deliver renewable projects at scale across the country, and this transaction furthers our plan to execute this vision.” 

The sale leaves the Canada-based Algonquin with a smaller, fully regulated profile that still includes its hydropower assets. 

“This transaction, coupled with the recent sale of our 42.2% ownership stake in Atlantica Sustainable Infrastructure plc on Dec. 12, 2024, achieves a pivotal step in our journey to transform AQN into a pure-play regulated utility with reduced complexity,” Algonquin CEO Chris Huskilson said. “Though there is still work to be done, passing this milestone should enable a greater focus on increasing the pace of this transition.” 

LS Power is forming a new subsidiary company called Clearlight Energy to manage the acquired operating wind and solar assets that are spread across the United States and Canada and include 44 projects with more than 3,000 MW. It will be run by Jeff Norman, who previously was president of renewables at Algonquin. 

Algonquin had 8,000 MW of renewable and storage projects under development around North America. Clearlight Energy will work on 1,800 MW of those, which include the Canadian projects and those that are co-located with existing assets. REV Renewables, a previously existing LS Power subsidiary, will get the other 6,200 MW of development projects in the United States, bringing its development pipeline to more than 21,000 MW. 

“The acquisition of these additional development projects complements REV’s objectives to develop renewable energy solutions that will transform our electric system,” REV Renewables CEO Ed Sondey said. 

The deal won approval from FERC in an order issued in December (EC24-111), which found the deal would be in the public interest. PJM’s Independent Market Monitor filed a report saying the combined firm would have market power in a subregion of the RTO, but the commission rejected its use. 

The IMM also wanted some behavioral requirements to mitigate the alleged market power, but FERC declined to impose them. FERC said the monitor’s issues were aimed more generally at its merger evaluations and market power protections in PJM, not the specific deal in front of it. 

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FERC Denies SPP’s Timing Waiver Request

FERC has denied SPP’s waiver request to allow the RTO’s interconnection customers without a pending request to ask for interim interconnection service during a period when the study queue cluster’s window is closed.

In an order issued Jan. 3, the commission rejected SPP’s contention, saying its request did not meet FERC’s criteria for granting waivers (ER24-2863).

The commission found SPP’s request does not address a concrete problem because the proposed waiver would not permit entities without an interconnection request to ask for interim interconnection service. It said SPP did not seek a waiver of the term “interconnection customer,” putting it in conflict with tariff language that applies specifically to interconnection customers.

SPP filed the timing waiver request in August 2024. Clean energy associations and investor-owned utilities supported the grid operator’s request, saying it would help SPP clear its interconnection queue backlog in a fair, efficient and expeditious manner and could help provide greater certainty to interconnection customers.

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NPCC Gas-Electric Study Details Winter Reliability Challenges

A new study from the Northeast Power Coordinating Council (NPCC) outlines some of the major risks that reliance on natural gas generation poses for the New England power system and emphasizes the need for dispatchable resources to limit potential winter reliability issues. 

NPCC, which conducted the study in coordination with NYISO, ISO-NE, NERC and the Northeast Gas Association, found the gas system to be “fully utilized” throughout a three-day modeled cold stretch. 

However, if the cold snap lasts beyond three days, or key gas network outages occur at the same time, it likely will add “significant stress to the consolidated network of gas pipeline and storage infrastructure in New England and New York,” said NPCC CEO Charles Dickerson, adding that an extended cold stretch could put significant pressure on the region’s oil inventory and replenishment capabilities. 

Additionally, extreme, low-probability events causing the “near or total cessation of natural gas throughput,” such as the outage of a key pipeline or compressor station, may cause “catastrophic impacts for downstream customers,” NPCC wrote. 

During normal operations, the Northeast faces significant gas constraints in the winter, when much of the pipeline system is reserved for heating needs. 

“Since most generators do not have firm transportation entitlements, the ability of pipelines to provide intra-day scheduling flexibility to accommodate the twice-daily ramp during cold snaps should be questioned,” NPCC wrote.  

As renewables proliferate, NPCC found the ramping requirements in both New England and New York could surpass 7,000 MW by 2032. It projected that the increasing ramping needs “can generally be accommodated” in the long term under normal weather conditions. 

New England’s “duck curve” has increased in recent years due to the rapid expansion of behind-the-meter solar. ISO-NE surpassed 100 duck curve days for the first time in 2024, which are defined as days when mid-day demand is lower than overnight demand.  

In the winter, the two major liquified natural gas (LNG) import terminals servicing New England — Repsol’s facility in St. John, New Brunswick, and Constellation’s Everett Marine Terminal (EMT) located just north of Boston — remain “an integral part of the gas-fired generators’ ability to satisfy fuel assurance objectives,” NPCC found.  

LNG deliveries from the facilities “give pipeline operators valuable scheduling flexibility since they displace the need for conventional flows west-to-east into New England,” NPCC added. It estimated the two facilities can provide enough LNG to fuel 8,000 MW of gas generation.   

While EMT is under contract with the Massachusetts gas utilities though May 2030, the future of the import terminal is uncertain after the contract expires. When the Massachusetts Department of Public Utilities approved the contracts in May, it directed the utilities to work to reduce or eliminate their reliance on the facility in accordance with the state’s climate goals. (See Massachusetts DPU Approves Everett LNG Contracts.) 

NPCC singled out the Everett terminal as a particularly important facility for gas and electric reliability, writing that it plays a key role that could not be filled easily by additional imports from St. John or increased oil generation.  

“EMT’s location is ideal because it provides both pressure support and flow on an instantaneous basis, whereas Repsol Saint John cannot,” NPCC wrote. Although Repsol could pack the Maritimes and Northeast pipeline in the hours before an expected need, its facility is not able to provide the same real-time reliability support as EMT, NPCC said.  

While oil generation theoretically could replace the 2,600 MW of gas generation capacity supported by EMT, oil retirements over the next decade, combined with the potential loss of EMT, may increase the likelihood of capacity deficiencies, NPCC wrote. 

The NPCC’s findings echo some of the key results from ISO-NE’s Economic Planning for the Clean Energy Transition (EPCET) study, which the RTO released in October. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) 

The EPCET study emphasized the importance of maintaining an adequate amount of dispatchable generation on the grid to balance renewables and ensure reliability.  

“The grid of 2032 and beyond may sometimes require more dispatchable generation (either from stored fuels or an unconstrained fuel supply) than it has in recent winter conditions,” the EPCET study found.  

The EPCET study also found that the winter season likely will be the last to decarbonize due to factors including the high winter peak, need for dispatchable generation and high costs of existing clean firm generation resources.  

ISO-NE is overhauling its capacity market, with the intent of increasing compensation for resources that protect grid reliability during the most vulnerable periods. The reforms likely will add incentives for gas generators to contract for firm fuel, though it is unclear whether these incentives will change generator behavior.  

NCPP’s study also noted that offshore wind “has the potential to materially lessen reliance on oil and gas during the peak heating season.” Multiple New England states also are pursuing large-scale additions of battery storage, which should help lessen the reliance on gas to meet peak demands.  

“Uncertainty about the pace, amount and inevitability of electrification, electric vehicles and offshore wind in the years ahead may intensify operational stresses on the gas infrastructure available to serve gas-fired generation over the medium and long term,” NPCC concluded. 

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In Letter to Senators, BPA Tempers Markets+ Leaning

The Bonneville Power Administration tamped down expectations that it is all in on SPP’s Markets+, clarifying in a recent letter to lawmakers representing Oregon and Washington that it’s still weighing the pros and cons of joining a day-ahead market.

In a Dec. 31 letter publicly released by the agency Jan. 7, BPA Administrator John Hairston said it’s possible in the short term that BPA will not join a day-ahead market and “continue to market surplus power and make short-term purchases through bilateral trading and optimize real-time activity in [CAISO’s Western Energy Imbalance Market].”

“In the long term, we are concerned, however, that most of our potential trading partners will be in a day-ahead market themselves and create challenges in relying on a bilateral market,” Hairston added. “We will continue to evaluate the development of Western electric markets to assess the potential costs and benefits of participation.”

Hairston also reiterated that BPA would join a day-ahead market only if the market’s framework is compatible with the agency’s statutory obligations and other commitments, including environmental, reliability and affordability.

Hairston’s comments came after Democratic Sens. Jeff Merkley (Ore.), Ron Wyden (Ore.), Maria Cantwell (Wash.) and Patty Murray (Wash.) urged in a Dec.13 letter that the federal power marketing administration carefully weigh its choice between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM).

Markets+ and EDAM are vying for participants as they develop their market frameworks, with BPA leaning toward Markets+. Agency staff have recommended that BPA join Markets+, citing the market’s governance framework, which BPA believes provides greater independence from California state influence compared with the EDAM option.

However, the senators contended that the agency has failed to make a business case for Markets+, citing a BPA-commissioned study by consulting firm Environmental and Energy Economics.

That study, which relied on production cost analyses, found BPA would realize the most significant net economic benefits — $251 million in 2026 declining to $147 million in 2035 — in a “Westwide Market” scenario that includes California.

In his most recent letter, Hairston echoed arguments he’s made in correspondence with Seattle City Light, telling senators the study’s results “should be viewed with some skepticism” as the Western Interconnection likely will have two day-ahead markets, given that entities have signed agreements in favor of both Markets+ and EDAM.

Hairston added that numerous other elements not captured in production cost analyses can have an economic impact on expected benefits, such as governance structure, resource adequacy requirements, greenhouse gas accounting, fast-start pricing and scarcity pricing.

The Northwest region’s EDAM supporters also have criticized BPA’s apparent willingness to dole out $25 million to fund the Phase 2 implementation activities for Markets+ while declining to contribute $25,000 to the West-Wide Governance Pathways Initiative’s effort to bring independent governance to CAISO’s markets.

According to the senators’ letter, SPP has said the $25 million commitment is “essentially a market decision.” Hairston rebuffed this assertion in his most recent letter, saying “Phase 2 funding is not a commitment to joining Markets+; it is a commitment to continue funding development of the market.”

Similarly, he stated that BPA is, in fact, providing $25,000 to fund the Pathways Initiative but declined to make a public commitment before ensuring that the funding is “compatible with a different, much larger grant from the U.S. Department of Energy.”

Still, EDAM’s independence hinges on support from the California Legislature. Hairston noted, “It will be important to see if the Legislature will approve a full scope of independence.”

BPA will release a draft policy letter in March 2025 that will provide greater clarification on the agency’s final decision, according to the letter.

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NERC Submits Energy Assurance Standards to FERC

NERC has submitted two new reliability standards for FERC approval, both aimed at addressing the risks arising when energy resources with inconsistent output are unable to meet the demands of the grid and maintain reliability. 

The ERO filed BAL-007-1 (Energy reliability assessments) and TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) on Jan. 6, asking that the commission approve both standards, along with proposed definitions for the terms “energy reliability assessment” (ERA) and “near-term ERA.” If approved, the definitions will be added to NERC’s Glossary of Terms. 

NERC’s Board of Trustees approved the standards, their implementation plans and the definitions at its most recent open meeting Dec. 10, along with several other proposed standards. (See “Standards Approved for FERC Submission,” NERC Board of Trustees Briefs: Dec. 10, 2024.) 

BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources) and received segment-weighted approval votes of 81.53% and 92.77%, respectively, in a formal ballot round that ended Nov. 4. (See “Approved Standard to be Updated,” NERC Standards Committee Briefs: Nov. 13, 2024.) 

NERC began the project in response to the grid’s ongoing transition from traditional inertial generation resources to weather-dependent resources like solar and wind. The ERO said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources, which may suffer inconsistent output associated with the weather and volatility in load. 

It called BAL-007-1 “a step in transitioning to energy-based planning methods in the operations planning time horizon [by helping] achieve a level of consistency across the industry” in terms of planning methods and strategies. The standard would require BAs to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. 

Near-term ERAs required by the standard must include assessments of the resources necessary to serve demand while also providing operating reserves for the grid. An assessment period would begin no more than two days after the operating day, and cover between five days and six weeks. 

BAs would be able to specify the frequency of their ERAs. By default, all time periods must be covered, so that, for example, a near-term ERA that covers two weeks may be performed every two weeks or every other week, but not every three weeks, because this would leave a gap in coverage. This requirement may be waived if the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low. 

A BA could perform the near-term ERA for its work area alone or jointly with other BAs for all their areas together. NERC said this arrangement was meant to mirror partnerships that already exist between BAs for “other operations or planning activities and real-time operations.” 

The standard also lists minimum elements that BAs must include in near-term ERAs: 

    • forecast or assumed demand profiles; 
    • resource capabilities and operational limitations (including fuel supply); 
    • energy transfers with other BAs; and 
    • known grid transmission constraints that limit the ability of generation to deliver their output to load. 

The proposed changes in TPL-003-7 are relatively minor. NERC said they will “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.” 

As set forth in the proposed implementation plan, the ERO asked that FERC make TOP-003-7 effective the first day of the first calendar quarter that is 18 calendar months after the effective date of its order approving the standard, with BAL-007-1 to take effect six months later. This arrangement would provide six months for entities to collect the data needed for near-term ERAs and provide it to BAs before they are required to perform the assessments. 

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Delaware, US Wind Finalize $100M+ in Community Benefits

Delaware has finalized a benefit agreement with US Wind for allowing the developer to use a state park to run export cables from the offshore wind farms it hopes to build.

State officials announced Jan. 6 that the deal will be worth more than $128 million to the state and its residents over more than 20 years.

US Wind received key federal approvals in late 2024 for construction and operation of up to 2.2 GW of wind power generation capacity in three phases.

The developer has secured offshore renewable energy certificates from the state of Maryland for the first two phases, known as MarWin and Momentum Wind, rated at 1.1 GW combined.

US Wind’s 80,000-acre lease area sits at the latitude of northern Maryland, but the plan is to run the export cables farther north, to southern Delaware. US Wind wants to route them beneath a parking lot at the Delaware Seashore State Park, then under the Indian River Bay on their way to Delmarva Power and Light’s Indian River Substation in Dagsboro, Del.

The developer announced Dec. 10 that the state had approved three key permits to do this.

The Jan. 6 announcement by the state Department of Natural Resources and Environmental Control (DNREC) centered on compensation to Delaware for allowing it. The agreements include:

    • 150,000 renewable energy credits per year — estimated lifetime value of $76 million — transferred from US Wind to Delaware utilities to help them meet clean energy requirements, thereby lowering customer costs.
    • $40 million from US Wind over 20 years for coastal waterway dredging, clean energy workforce training, scholarships and resiliency and capital projects at state parks.
    • $12 million-plus in 25 years of lease payments to Delaware State Parks for the underground cables.

DNREC said indirect benefits to the state and its people over 20 years include up to $253 million in reduced electric costs for consumers and more than $200 million in transmission system upgrades.

Maryland is an enthusiastic supporter of offshore wind and has set an 8.5-GW goal for itself. But it has encountered the same headwinds as other states in trying to meet that goal. Ørsted has placed its Skipjack Wind plan on indefinite hold amid challenging economics, and Maryland has allowed US Wind to seek higher compensation so it does not succumb to those economic challenges.

There also is the inauguration in two weeks of a president who has been openly hostile to offshore wind development, which may complicate or delay development of MarWin and Momentum. Donald Trump doubled down on his campaign trail rhetoric Jan. 7, telling reporters he wants zero wind turbines erected during his administration.

Closer to home, there is some popular opposition to wind development off the Delmarva shoreline.

Local media have reported that Sussex County denied a US Wind subsidiary the permit it needs to build a substation, that Ocean City is suing to reverse federal approval of the project, and that opponents have appealed DNREC’s approval of the export line’s placement.

But Delaware focused on the positive in its Jan. 6 announcement. DNREC Secretary Shawn M. Garvin said in the news release:

“The DNREC State Energy Office’s recently released State Energy Plan emphasizes the need for offshore wind development in order to reach our emissions reduction goals, and the need to consider partnerships with other states and wind project developers to reduce costs. Additionally, the funding for dredging, resiliency and parks projects and workforce training will provide needed resources to protect and preserve Delaware’s natural resources for decades to come.”

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DC Circuit Rejects Challenge to FERC Approval of Indiana Pipeline

A three-judge panel of the D.C. Circuit Court of Appeals issued a decision Jan. 7 that sided with FERC in an appeal of the agency’s decision approving a natural gas pipeline in Indiana. 

The pipeline was proposed to serve new natural gas units the state had approved to replace a retiring coal plant. Citizens Action Coalition of Indiana argued that FERC failed to analyze non-gas alternatives before approving the pipeline. 

“We disagree,” the court said. “Congress gave FERC authority to promote the development of interstate natural gas pipelines, but it left the choice of energy generation to the states. The purpose of the pipeline was to support Indiana’s energy plan, and FERC has no statutory authority to consider non-gas alternatives already rejected by the state.” 

The win by FERC follows losses on other pipeline cases at the D.C. Circuit, including a New Jersey one in which the commission approved new pipeline capacity that the state opposed on the grounds that it clashed with its climate policies. (See DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections.) 

The Natural Gas Act requires FERC to approve a pipeline if it determines the project is “required by the present or future public convenience and necessity.” It also can approve a project when its public benefits outweigh its adverse impacts. 

Indiana regulators in 2017 approved CenterPoint Energy’s integrated resource plan, which included a proposal to replace coal generators at its A.B. Brown Generating Station with solar and natural gas facilities. The utility initially wanted an 850-MW gas-fired unit, but state regulators rejected that plan and approved two smaller gas turbines that together produce 460 MW. 

“That brings us to the pipeline at issue here,” the D.C. Circuit decision said. “CenterPoint contracted with Texas Gas Transmission to supply natural gas to the planned units. Texas Gas then applied to FERC for approval of a 24-mile pipeline crossing the Ohio River and connecting the A.B. Brown site to an existing pipeline system in Kentucky.” 

FERC approved the pipeline after performing an environmental impact statement. Citizens Action filed for rehearing on the grounds the commission failed to consider alternatives to the gas units, failed to determine the impact of emissions, was wrong to net the drop in emissions from replacing coal with gas, and failed to properly balance environmental impacts with its public convenience and necessity determination.

The National Environmental Policy Act does not require FERC to consider non-gas alternatives that are outside its jurisdiction and would fail to serve the purpose of the project. 

“The project seeking certification from FERC is not the natural gas units, but the pipeline serving those units,” the court said. “Before Texas Gas applied for a certificate, CenterPoint and the Indiana commission had already determined that the public interest would be best served by the construction of natural gas units that ensure grid reliability and support the move to wind and solar generation.”  

FERC rejected Citizens Action’s request that the project be defined as promoting solar and wind, saying detailed evaluations of other power generation alternatives are separate questions from the pipeline proceeding. 

“More to the point, FERC could not lawfully define the project’s purpose as broadly as Citizens Action requests because Congress has not authorized FERC to choose between electricity generation resources,” the court said. “The NGA empowers FERC to approve new gas pipelines. It does not permit FERC to regulate the energy generation facilities those pipelines supply.” 

States have the authority to choose their preferred mix of generation, leaving the CenterPoint turbines outside of FERC’s jurisdiction, the court found. 

FERC did assess whether the gas turbines could be served adequately by existing pipelines and looked into alternative routes, which the court said showed it “adequately considered alternatives.” 

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Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO

FERC authorized another hefty penalty concerning demand response violations in the MISO capacity market, this time approving an $18 million settlement over Voltus reportedly falsifying registrations and overstating capacity from 2016 to 2020.

Voltus — the first retail customer aggregator to participate in MISO capacity auctions — and FERC finalized a settlement Jan. 6 that has Voltus paying a $10.9 million civil penalty and reimbursing $7.1 million in profits to settle allegations that the company manipulated MISO’s demand response market (IN21-10). The settlement also directs Voltus co-founder and former CEO Gregg Dixon to pay a $1 million fine and step down from the Voltus Board of Directors.

Additionally, Voltus must file annual compliance monitoring reports to FERC enforcement staff for two years, with the potential for another two years of monitoring reports beyond that.

Voltus announced in early 2024 that Dixon stepped down as CEO but would remain on the company’s board of directors.

FERC’s Office of Enforcement concluded Voltus inappropriately gained access to customer data and used it to deceptively register load-modifying resources over four MISO capacity auctions. It said both Voltus and Dixon cooperated with its investigation, which began in 2021.

FERC staff said under Dixon’s direction, Voltus employees registered Ameren Illinois ratepayers as load-modifying resources without their knowledge or consent. Employees used Ameren account numbers on the utility’s website to download data required by MISO to register them.

Dixon reportedly learned from an employee sometime before MISO’s 2017/18 capacity auction that non-public data on Ameren’s customers could be obtained by registering as an Ameren business partner and then entering customer account numbers on its website.

According to Dixon, Ameren had “advanced metering infrastructure and meter data available” that enabled Voltus to “measure performance for dispatches of demand response without having to install our technology.”

Voltus in late 2016 rolled out what it called “Operation Violet” with a goal of selling 200 MW of demand reduction in MISO’s Zone 4 in southern Illinois. Voltus in some cases requested copies of Ameren customers’ utility bills to conduct analyses of what they could earn by participating in DR, FERC said, and noted that the bills contained account numbers.

For legitimate customers who entered Voltus’ aggregation program, FERC staff said Voltus employees — again at Dixon’s direction — would inflate on paper the levels of curtailment that the customers agreed to provide. FERC said Voltus employees registered some resources as if they would completely shut down if called upon without regard to whether that was possible or whether resources had agreed to it in their contracts.

According to FERC, a third-party contractor Voltus hired to help manage demand response registrations reportedly became uncomfortable over the possibility for fines and the “reputational risk for Voltus” and resigned in early 2017.

‘Scranta’

By summer 2017, Voltus had designed a computer program named “Scranta” based on a portmanteau of “scrape” and “Santa,” which scraped data from Ameren by submitting “tens of millions” of potential account numbers to the website. When the program landed on a genuine account number, it would collect customer data for a Voltus database.

When Voltus found accounts with peak demand above 50 kW, those accounts were added to an automated email distributed to Voltus leadership and a sales team to either become leads or involuntary participants in Voltus’ demand response program.

FERC said a Voltus employee sent an August 2017 email stating, “We should exercise caution increasing the scraping rate, as it would be very easy for [Ameren] to make this much harder for us with some simple server config changes.”

FERC said in its first MISO Planning Resource Auction for 2017/18, Voltus registered about 41 MW of load modifying resources without contracts. After rolling out Scranta, Voltus registered an uncontracted 207 MW with MISO in the 2018/19 PRA, 216 MW in the 2019/20 PRA and 65 MW in the 2020/21 PRA. The uncontracted megawatts included some resources that Voltus approached with unsuccessful sales pitches.

FERC said uncontracted or above-contract demand response made up 96% of Voltus’ MISO portfolio in the 2017/18 planning year, 49% in the 2018/19 planning year, 45% in the 2019/20 planning year and 29% in the 2020/21 planning year. FERC said over those years, MISO didn’t require aggregators to prove they had contractual relationships with the load-modifying resources they claimed to have at the ready.

FERC staff said Dixon acknowledged in testimony that Voltus didn’t know whether its DR resources without legitimate contracts would respond to MISO dispatch by reducing demand.

“I … noticed that you could just plug in any account number, that, you know, you could go to the [Ameren] website and just plug in — you know, you could essentially script the URL. It’s a 10-digit account number code. You could plug that in, just cycle through them, and it would identify — we created a program that would identify any loads,” Dixon told FERC staff during the investigation.

In an early 2019 Slack conversation with Voltus employees, Dixon likened the unauthorized DR registrations to his hobby clearing mountain biking trails on a nature preserve. Dixon said because he didn’t have explicit permission to cut new paths, he would work under the cover of darkness to clear brush.

An unnamed Voltus employee reportedly responded with, “If we sat around waiting for MISO to create the perfect rules for DR and always played by their exact rules there wouldn’t be DR in MISO at all!”

Parallels with Ketchup Caddy

The settlement is the latest in a string of disciplinary action from FERC regarding companies deceptively offering demand response in MISO’s capacity auctions.

This also is the second time Ameren’s website has been connected to phony demand response schemes in MISO. From 2019 to 2021, the founder of an obscure, Texas-based LLC meant to sell in-car ketchup holders used a random number generator on an Ameren website to land on actual customer accounts and cull data for fraudulent DR registrations. (See In a Pickle: FERC Issues $27M in Fines over Ketchup Caddy DR Deceit.)

Ameren did not return RTO Insider’s request for comment on whether it has addressed vulnerabilities within its website that allow companies to use random number generators to reveal customer account numbers and gain access to usage data.

Voltus Neither Admits nor Denies

Voltus said the settlement should not be construed as it admitting to market manipulation.

“Under the terms of the settlement agreement, we are not acknowledging wrongdoing in connection with bringing demand response to MISO for the first time. We have not been accused of, let alone admit to, any market manipulation. Rather, we are entering a no-admit/no-deny settlement on tariff violations. Moving forward, we will continue to act according to the letter and spirit of all applicable laws, regulations and market rules,” the company said in an emailed statement to RTO Insider.

In its order approving the consent agreement, FERC cited the conclusions of an investigation by its enforcement office that singled out Dixon: “Enforcement has concluded that Dixon violated the Anti-Manipulation Rule, 18 C.F.R. § 1c.2, during the Relevant Period by engaging in a fraudulent scheme to obtain capacity payments from MISO that included (1) improperly obtaining customer data and using that data in connection with jurisdictional transactions, (2) registering LMRs to which Voltus lacked contractual rights, and (3) offering uncontracted LMRs into the PRA. Enforcement has concluded Dixon made, and allowed Voltus employees under his control to make, false and misleading statements to MISO, customers and potential customers, and others, in furtherance of this fraudulent scheme. Enforcement has concluded Dixon knew, or was reckless in not knowing, that this fraudulent scheme violated the terms and requirements of the MISO Tariff.”

Voltus said with the settlement behind it, its “team is free to put its undivided focus on creating opportunities for customers and on delivering a more reliable, affordable and sustainable electric grid.”

“Voltus will continue to work with regulators, including FERC, to ensure that tariffs that govern demand-side resources are clear and consistently applied,” the company said.

Voltus said it remains proud of the $175 million it has paid customers over the past nine years, “much of which comes from markets that previously did not allow demand response.”